Reservoir Core Research Articles

Prediction method and application of shale reservoirs core gas content based on machine learning

To improve the recovery of shale gas, it is very important to accurately grasp the gas content of shale reservoirs. Considering the problems of low accuracy, strong local limitation and poor adaptability of seismic data of traditional methods such as empirical formulas and regression fitting. Based on machine learning (ML) algorithms such as support vector regression, decision trees, random forests, BP neural networks and convolutional neural networks, an intelligent prediction method of shale reservoir core gas content based on machine learning was established by using three parameters: P-wave velocity (Vp), S-wave velocity (Vs) and density (RHOB). It was compared with traditional method prediction, core tests and other gas content data, which verified the effectiveness and high-precision characteristics of the method. Additionally, in support vector regression (SVR), decision tree (DT), random forest (RF), BP neural network (BP), convolutional neural network (CNN) and other machine learning algorithms, the support vector regression algorithm was the most stable, robust and accurate. Because it takes the easy-to-obtain “three parameters” as input data and retains the gas content characteristics of core data, it also has strong generalization ability and easy migration advantages, which can be easily extended to gas content prediction of three-dimensional shale reservoirs based on seismic inversion data. The prediction results of this method in the core gas content of the shale reservoir of the Wufeng Longmaxi Formation in the southern Sichuan Basin show that compared with the traditional method, the gas content prediction accuracy based on the machine learning algorithm was higher. Therefore, it can provide method support for shale reservoir target optimization and drilling deployment.

Quantitative Characterization of the Lower Limit of the Physical Properties of Tight Oil Reservoirs in Nano-Material Porous Media

Tight oil is an unconventional petroleum resource, which occupies a essential position in the global energy structure. The main purpose of this paper is to quantitatively characterize the lower limit of the physical properties of tight oil reservoirs in nanomaterial porous media. This paper starts with the single-phase deionized water flow experiment in micro-nano-quartz tube, combined with the tight oil reservoir core single-phase simulation, formation water seepage experiment, analyzes and characterizes the low-velocity and nonlinear seepage characteristics of tight reservoir fluid. At the same time, combined with the dynamic network simulation technology, the process of water flooding in tight oil reservoirs under different conditions is simulated, and the influence of each influencing factor on the two-phase seepage of water flooding is determined. In addition, combined with different water injection capillary numbers, water flooding nuclear magnetic resonance experiments, the dynamic characteristics and distribution changes of oil and water, in two phases in the water flooding process are analyzed, and the simulation results are used for verification and analysis, to indicate the reasonable and efficient water flooding development of tight oil reservoirs.

Fluid Inclusion Constrained Multiple Petroleum Chargings in the Lithologic Reservoirs of the Late Eocene Shahejie Formation in the Minfeng Sag, Bohai Bay Basin, East China

The fluid inclusion technique was utilized to reveal the petroleum charging events in the lithologic reservoirs embraced in the Late Eocene Shahejie Formation of the Minfeng sag, Bohai Bay Basin, East China. Petrography, fluorescence microspectrometry, and microthermometry were systematically carried out on 15 double-polished thin sections handled from reservoir core samples of the third Member of the Shahejie Formation. The results show that three generations of petroleum inclusions with fluorescence colors of yellow, yellowish green and bright blue were entrapped along the healed fractures in detrital quartz grains of these samples. The fluorescence features of petroleum inclusions illustrate that inclusion oils have different maturities and were products of source rocks at different stages. In addition, the trapping time of petroleum inclusions was determined by combining the homogenization temperatures of their coeval aqueous inclusions with thermal-burial histories. By integrating the petrographic occurrence, characteristics of petroleum inclusions, and the maturity and the trapping time of the studied inclusion oils, it is jointly constrained that the lithologic reservoirs of the Late Eocene Shahejie Formation in the Minfeng sag underwent three petroleum chargings, which occurred during 37.8~25 Ma, 11.7~3.5 Ma and 1.4~0.1 Ma, respectively. The petroleum from each charging period migrated from the center of the sag to the edge, and the lower the maturity of the migrating petroleum, the longer the migration duration.

Reservoir Physical Properties and Micropore Nanocharacteristics of Cores in the Shihezi Formation, Sudong District, Sulige Gas Field, Ordos Basin.

Sulige gas field is a very complex large-scale gas field with low porosity, low permeability, low abundance, and strong heterogeneity. In this study, the nanopore structure of the reservoir in the study area was analyzed. The analysis of reservoir physical properties and core microscopic pore characteristics of Shihezi formation in Sudong District, Sulige gas field, Ordos Basin, was put forward. According to core observation, thin section identification, and grain size analysis, the lithology of gas reservoirs in Shan-1 member and He-8 member in the study area is mainly lithic sandstone, lithic quartz sandstone, and quartz sandstone. According to the analysis of physical data in the study area, the reservoirs in Shan-1 member and He-8 member have typical characteristics of low porosity and low permeability. According to that microscopic observation of sandstone thin section and cast thin section combined with the analysis of scan electron microscope, the results show that both Shan-1 member and He-8 member of Sudong area 2 in Sulige gas field are dominated by class I reservoirs and class II reservoirs. Especially, class I reservoirs are widely distributed, with the cumulative area of this type of reservoirs accounting for 70.12% of the total area in Shan section and 64.12% in He-8 section. Class I reservoirs are scattered in the study area, accounting for 0.27% of the total area in the mountain section and 0.36% in the He-8 section. Class IV reservoirs are distributed dispersedly and have a small distribution area. The cumulative area of reservoirs in mountain section accounts for 5.38% of the total area and that in He-8 section accounts for 5.46%. Therefore, Sudong area 2 in Sulige gas field is a typical low porosity and low permeability reservoir. On the basis of geological background, sedimentary microfacies, diagenesis, and pore structure characteristics of the study area, it is considered that the pore structure of sandstone in the study area is mainly controlled by sedimentary characteristics and diagenesis of sandstone.

An Improved Model for Evaluating the Brittleness of Shale Oil Reservoirs Based on Dynamic Elastic Properties: A Case Study of Lucaogou Formation, Jimusar Sag

Rock brittleness is a critical factor affecting the stimulation of shale oil reservoirs. For efficient development of the shale oil in Lucaogou Formation, Jimusar Sag, the brittleness of the sweet spots needs to be evaluated. In this paper, the triaxial compression, acoustic wave measurements, and three-point bending tests were carried out on the reservoir cores. Based on the prepeak energy characteristics of the stress-strain curve, the brittleness of different horizons was calculated, with the largest difference of 24.89%. An improved model based on dynamic elastic properties was proposed to evaluate the brittleness along the vertical pay zones, by which the continuous brittleness in the upper sweet spot was found more changeful than that in the lower sweet spot. The linear correlation coefficient between the brittleness from the improved model and that from the laboratory tests is 0.85, improving the accuracy by 21% and 27% respectively, compared with the conventional elastic property methods. From the characteristics of compression fractures and the length of the fracture process zone, it was found that the compression fractures were more complex and the fracture process zone length was shorter in a more brittle rock, verifying the reliability of the improvement model. The improved method based on dynamic elastic properties proposed in this paper is expected to guide the brittleness evaluation in other regions.

Influences of SO2 contamination in long term supercritical CO2 treatment on the physical and structural characteristics of the Zululand Basin caprock and reservoir core samples

Understanding the mineral and microstructure changes in sandstone samples during supercritical CO2 gas treatment is an important aspect of geological CO2 sequestration. To gain insight into the effects of SO2 contamination in CO2 in South Africa, two core samples extracted from the reservoir lateral seal (ZC) and Cenomanian sandstone aquifer (ZG) within the Zululand Basin were studied. The samples were treated with CO2 and CO2/SO2 gas streams at typical reservoir temperature and pressures (10 MPa and 316 K, and 17,5 MPa and 346 K) under supercritical conditions. High pressure Parr reactors were used for storing the rock-gas-water mixtures for up to two months using a water:rock ratio of 23:1. Tests were conducted using pure CO2 and a 99% by weight (wt.) CO2 and 1% (wt.) SO2 mixed gas stream. Due to the prohibitive costs associated with CO2 purification, the knowledge of the consequences of key impurities relevant to geological sequestration is critical. Pre-and post- CO2/CO2–SO2 treatment characterisation was conducted using X-ray Diffraction (XRD) Analyses, Fourier transform infrared spectroscopy (FTIR), and low-pressure gas adsorption (LPGA). Varying mineral alterations were observed in the CO2 treated samples, mainly comprising of calcite, plagioclase and smectite dissolution and the precipitation of quartz, plagioclase, calcite and smectite. Dissolution pores and pore clogging were observed and increased microstructure heterogeneity was reported. Increases in the adsorption capacity, surface area and pore volume were observed in all samples. After treatment with CO2–SO2 gas mixture, increases in mineral reactivity were observed in the ZC sample along with gypsum precipitation, indicating potential improvement in the lateral seal's self-sealing capacity. The introduction of SO2 lead to the increase in quartz and plagioclase precipitation and increased dissolution of smectite and stilbite in the ZG sample. The study presents a novel investigation of the changes expected to take place during CO2 injection in sandstone basins.

Quantification of the Fracture Complexity of Shale Cores After Triaxial Fracturing

Diagnosing fractures under compression is of great importance in optimizing hydraulic fracturing stimulation strategies for unconventional reservoirs. However, a lot of information, such as fracture morphology and fracture complexity, is far from being fully excavated in the laboratory limited by the immature fracture identification techniques. In the current study, we propose a set of methods to analyze the fracture complexity of cylindrical cores after triaxial fracturing. Rock failure under conventional compression tests is real-time controlled by monitoring the stress–strain evolutions to ensure that the cores remain cylindrical after failure. The lateral surface of the core cylinders is scanned with a 2D optical scanner to extract the fracture parameters, surface fracture rate, and inclination dispersion, which are normalized and averaged to derive the fracture complexity. After analyzing the data for 24 shale gas reservoir cores from the Sichuan Basin, the fractal dimension of fracture images shows a good linear correlation with the surface fracture rate but has no correlation with the dip dispersion. The calculated fracture complexity has nearly no relationship with the E-v–based brittleness index but demonstrates a positive correlation with the mineral content–based brittleness index. Moreover, the fracture complexity is associated with the core mineralogical compositions. The fracture complexity is positively correlated with the content of quartz, calcite, and dolomite and negatively correlated with the content of clay minerals and has no obvious relationship with the content of feldspar. The proposed method provides an experimental basis for the evaluation of fracturability of unconventional oil and gas reservoirs.

MICROBIAL EOR STUDY TO IMPROVE SWEEP EFFICIENCY IN CALTEX FIELDS PHASE 1 – NUTRIENT SELECTION

The objective of this research is to find a cost effective nutrient that will stimulate the growth of in-situ microbes in Caltex Pacific Indonesia (CPI) oil fields to create sufficient biological products to plug high-permeability reservoir thief zones. If successful, injection fluids may be diverted into unswept regions of the reservoir, increasing the sweep efficiency und extending the production life of watered- out oil fields. This paper describes how a wide range of nutrients were researched and tested in the laboratory to achieve the objective. The primary findings of this study show that several primary nutrients were successful at creating bioproducts at high temperature, low salinity, reservoir conditions, and that molasses may be the most cost effective nutrient for all three CPI waterflooded reservoirs tested: Balam South, Bangko, and Minas fields. As a result of this work, laboratory studies were started to see to if the microbial growth created in laboratory test tubes can be recreated within reservoir core plugs to achieve sufficient permeability reduction to justify field trial (s). The core flood process and techniques will be presented in a separate paper.

Adsorption Study of Novel Gemini Cationic Surfactant in Carbonate Reservoir Cores-Influence of Critical Parameters.

Surfactant flooding is an enhanced oil recovery method that recovers residual and capillary trapped oil by improving pore-scale displacement efficiency. Low retention of injected chemicals is desired to ensure an economic and cost-effective recovery process. This paper examines the adsorption behavior of a novel gemini cationic surfactant on carbonate cores. The rock cores were characterized using an X-ray diffraction (XRD) spectroscope. In addition, the influence of critical parameters on the dynamic adsorption of the cationic gemini surfactant was studied by injecting the surfactant solution through carbonate cores in a core flooding apparatus until an equilibrium state was achieved. The concentration of surfactant was observed using high performance liquid chromatography. Experimental results showed that an increasing surfactant concentration causes higher retention of the surfactant. Moreover, increasing the flow rate to 0.2 mL/min results in lowering the surfactant retention percentage to 17%. At typical high salinity and high temperature conditions, the cationic gemini surfactant demonstrated low retention (0.42 mg/g-rock) on an Indiana limestone core. This study extends the frontier of knowledge in gemini surfactant applications for enhanced oil recovery.

Coreflood Tests to Evaluate Enhanced Oil Recovery Potential of Wettability-Altering Surfactants for Oil-Wet Heterogeneous Carbonate Reservoirs

Summary Oil-wetness and heterogeneity are two main factors that result in low oil recovery (OR) by waterflood in carbonate reservoirs. The injected water is likely to flow through high-permeability regions and bypass the oil in the low-permeability matrix. In this study, systematic coreflood tests were carried out in both “homogeneous” cores and “heterogeneous” cores with a wettability-altering surfactant. The homogeneous coreflood tests were conducted to evaluate surfactant retention, as well as to compare tertiary surfactant flooding with secondary surfactant flooding. The heterogeneous coreflood test was proposed to model bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. Surfactant retention results suggest that retention increases as initial oil saturation decreases. The retention of selected surfactant in the target reservoir cores was measured to be within a range of 0.07–0.12 mg/g-rock, which is economically acceptable. The results of homogeneous coreflood tests showed that both secondary waterflood and secondary surfactant flood can achieve high OR (>50%) from relatively homogeneous oil-wet cores. A shut-in phase after the surfactant injection resulted in a surge in oil production, which suggests that enough time should be given for wettability alteration by surfactants. The results of heterogeneous coreflood tests showed that more oil is bypassed in the tighter matrix by waterflood if the permeability is higher in the flooded layer and this bypassed oil is the target for the wettability-altering surfactant floods. Slow wettability-altering surfactant injection leads to imbibition into bypassed regions. When the oil-wet carbonate reservoirs have large unswept regions after waterflood, wettability-altering surfactants can significantly improve OR if enough time is given for imbibition.

Mechanistic Study on the Decrease in Injectivity during Salt-Resistant Polymer Flooding.

According to numerous laboratory experiments and field applications, polymer flooding can effectively modify the liquid absorption profile and increase the sweep efficiency, thereby enhancing the oil recovery. However, long-term injection of polymers decreases the effective permeability of the reservoir and plugs the formation pores, resulting in irreversible reservoir damage. In the development process, polymer types and concentrations must be selected according to the reservoir to avoid problems such as plugging of the formation pores. This study was aimed at clarifying the degree of plugging and the injection limit of the reservoir when a salt-resistant polymer (SRP) is used in production processes of the Daqing Oilfield. To this end, oil displacement experiments, dynamic and static adsorption experiments, and SEM observations were performed using representative reservoir fluid and core samples. The static adsorption of “medium-molecular” SRP reached equilibrium after 36 h, and the saturated adsorption capacity was 3.56 mg/g, which was approximately 2–5 times the dynamic adsorption capacity. For medium-molecular SRP, with a molecular mass of 7 million, the lower limit of the core permeability was 20–40 mD. When the permeability was less than 100 mD, the SRP concentration injected into the core could not exceed 900 mg/L. The oil displacement capacity of SRP decreased owing to the macromolecular hydration radius and the strong aggregation effect of SRP. Polymer adsorption and the retention of sand-carrying critically decreased water permeability. This study provides insights into SRP flooding under different geological conditions in the Daqing Oilfield and can help clarify the molecular mass and concentration of polymers with changes in the reservoir conditions.

Experimental Investigation of Low-Concentrated Nanocomposite Polymer Gels for Water Shutoff Treatment Under Reservoir Conditions

Summary Excessive water production is one of the main challenges in mature oil fields. Applying polymer gels has proven to be an effective chemical treatment to this problem. Because of some limitations in application of polymer gels in oil reservoirs with harsh conditions, using nanoparticles (NPs) in gel structure has been proposed recently to improve the performance of such systems. However, while main body of the previous studies has only focused on improvement of bulk properties of polymer gels in presence of NPs, there is a serious lack of data on their performance in porous media. In this study, we have conducted a comprehensive investigation on application of two new nanocomposite polymer gels through bulk-gel static tests and dynamic core displacement tests. Fe2O3 and NiO NPs at low concentrations (<100 mg·L−1) in AN125VLM/chromium acetate polymer gel system were used. The results of bulk bottle tests at 82℃ demonstrated that the nanocomposite gel systems have the same gelation time and gel strength as the NPs-free gel. Swelling ratio measurements were also performed in a high-salinity formation water (268 949 mg·L−1), and accordingly, while NiO NPs deteriorated the swelling behavior of the gel system, Fe2O3 NPs showed a positive impact. The results of the strain-sweep test demonstrated relatively similar linear viscoelastic region and thus the same gel strength for all gel samples. In addition, the results of the thermogravimetric analysis (TGA) revealed that Fe2O3 NPs had a minor positive impact on thermal resistance of the polymer gel system. Finally, high pressure-high temperature coreflooding experiments were carried out on three sandstone reservoir core samples. Although the NPs-free gel showed a desirable level of disproportionate permeability reduction, the injection of Fe2O3 nanocomposite gel showed unsatisfactory results and caused rock permeability degradation. The pressure drop trend and deposition of polymer gel particles at the upstream injection side confirmed the aggregation and plugging effect of NPs during injection. Our findings demonstrate the critical aspect of dynamic core displacement testing of nanocomposite gels before their use for field applications.

Modeling of microflow during viscoelastic polymer flooding in heterogenous reservoirs of Daqing Oilfield

Viscoelastic polymer flooding has been extensively used in oilfield development as an enhanced oil recovery method. Understanding the microflow mechanism is necessary to promote the polymer displacement effect and design the polymer flooding scheme. Previous studies have investigated polymer flooding mechanisms, such as a favorable mobility ratio and increasing sweep efficiency; however, the elasticity effect on displacement efficiency is still unclear, particularly in a heterogeneous reservoir. Class II reservoirs, which have an effective thickness between 1 and 4 m and a permeability greater than 100 mD, have recently become the target zones of polymer flooding in the Daqing Oilfield. Class II reservoirs are subdivided into type A and B oil layers. Compared with the type A oil layer, type B has a larger permeability contrast, more severe heterogeneity, and worse connectivity. There are considerable differences between types A and B in the actual development of polymer flooding as well as between type B oil layers of different oilfield blocks. Thus, it is necessary to investigate the factors that influence the micro-oil displacement mechanism. In this study, local and global micro-pore models are established based on a computed tomography scan slice of Class II reservoir cores, and mathematical models of the viscoelastic polymer and oil two-phase flow in porous media are established. The log conformation method is used, which can effectively enhance convergence, owing to a high relaxation time inducing high non-linear of equation. The volume-of-fluid method is used to track the interface between the two phases. The governing equations are solved using the OpenFOAM platform, which is open-source software written in C++. Then, the influences of pore structure and polymer elasticity on displacement characteristics are studied. The simulation results revealed that owing to the pore structure, the micro-oil displacement efficiencies of B_GI and B_PII, which belong to the type B oil layer, are lower than that of A_SIII, which belongs to type A, by 26.8% and 10.9%, respectively. The oil displacement efficiency of a commingled production comprising B_PII and B_GI is 4.0% and 15.6% lower than that of single-layer productions of B_PII and B_GI, respectively. The oil displacement efficiency increases by 6.45% when the relaxation time increases from 0.5 to 2 s and decreases when the relaxation time increases from 2 to 10 s. Therefore, by combining the micro-oil displacement efficiency and injectivity of a high-molecular-weight polymer, the optimum relaxation time is determined to be 2 s. The obtained results are significant for the design strata of a commingled production scheme and the optimization of polymer solutions in the type B oil layer of the Daqing Oilfield.

Experimental Study on Oil Drop Discharge Behavior during Dynamic Imbibition in Tight Oil Sandstone with Aid of Surfactant

The pore and throat structure of tight oil reservoir cores is complex, and the resistance of oil drop to discharge from the core is very high during dynamic imbibition. Surfactant has good ability in interfacial tension reduction and wettability reversal. It can reduce oil drop discharge resistance and enhance oil recovery effectively during dynamic imbibition in tight reservoirs. Here, we first analyzed the pore throat structure and mineral composition of tight core, and then the oil drop visualization instrument was used to study the discharge behavior of oil drop during dynamic imbibition. The oil drop discharge form was analyzed, and the influence of various factors on the oil drop discharge behavior was explored, and then the dynamic imbibition performance of surfactant in tight cores was obtained. The core throat diameter was mainly distributed in 0.07–1.1 μm, and the hydrophilic mineral content in core reached 50.8%. In the case of fluid flow in fracture, the oil drop discharge from near fracture matrix was faster, and its growth rate in height and width was faster than that without external fluid flow. Within a certain range, with the increase of IFT, the rate of core imbibition increased gradually. When the IFT increased from 0.32 mN/m to 0.59 mN/m, the oil drop rapture time decreased by 66.3%. The growth rate of oil drop discharged from the top and side of the core was faster than that from the bottom surface. Furthermore, it was easier to discharge. With the core thickness reduced by half, the rapture time of oil drop was reduced by 74.7%. For tight reservoirs, hydraulic fracturing can create more fracture surfaces and reduce the size of matrix blocks, which contributes to reduce the oil drop discharge resistance during imbibition and improve the oil recovery. This study provides a basis for surfactant to improve dynamic imbibition and oil production performance of tight sandstone oil reservoir.

Experimental Study of the Flow Mechanism of Deep Lacustrine Carbonate Reservoirs in the Yingxi Area of the Qaidam Basin

Many of the exploration and development theories derived for conventional clastic rock reservoirs are not applicable to pore-fracture lacustrine carbonate reservoirs. The fluid flow mechanisms under reservoir conditions are still unclear. Therefore, in this study, the rock samples were characterized using X-ray diffraction (XRD), porosity-permeability analysis, scanning electron microscopy (SEM), plain thin sections, and casting thin sections. The core samples were classified into two types (fractures and matrix pores) based on their reservoir spaces. The core flow experiments were performed under reservoir conditions using reservoir core plugs. The experimental results demonstrate that the cores, especially the fractured cores, have a strong stress sensitivity. The oil phase flow in the core has the characteristics of non-Darcy flow, and the threshold pressure gradient is 0.01–0.003 MPa/m. Additionally, for the oil-water two-phase flow in the fractured core, the water phase relative permeability of the residual oil is high. In contrast, the water phase relative permeability of the matrix core is less than 0.2. The nuclear magnetic resonance (NMR) transverse relaxation time ( T 2 ) spectra were used to analyze the differences between the water flooding characteristics of the two pore structures. The experimental results show that the peaks of the T 2 spectra after water flooding are lower than those before water flooding, and the matrix cores have a better oil displacement effect. The relaxation time of 0.1–10 ms makes the greatest contribution to the water flooding efficiency. The micropores smaller than 10 μm in diameter play an important role in the water flooding of the matrix core. These results will provide theoretical basis for solving the difficult problems of developing deep lacustrine carbonate reservoirs.

Low salinity surfactant alternating gas/CO2 flooding for enhanced oil recovery in sandstone reservoirs

Surfactant alternating gas/CO2 (SAG) flooding is a promising enhanced oil recovery (EOR) technology, which has the potential to improve oil production beyond primary and secondary water flooding methods. However, the performance of SAG flooding is restricted due to instability under high salinity reservoir conditions and excessive surfactant adsorption. One convenient and relatively low-cost option to overcome the limitations and improve the performance of SAG flooding is the use of low salinity water (LSW). In this study, an innovative and effective approach in the form of a low salinity surfactant (LSS) system was developed to suitably enhance the efficacy of immiscible SAG flooding in sandstone reservoir cores. The impact of LSS solutions on various mechanisms responsible for EOR including surface and interfacial tension (IFT), wettability alteration, CO2-foam stability, and surfactant adsorption were investigated. The initial IFT measurements revealed that oil-water IFT could be lowered using low salinity formation water (FW), however a more effective reduction was possible only when surfactants were introduced in such a system to form LSS solutions. Similarly, reductions in the contact angle (from initial 122° to 45°) were achieved with LSS solutions which demonstrated favorable wettability alteration of the reservoir rock from oil-wet to water-wet conditions. Foam stability experiments revealed that the half-life of CO2-foams generated with LSS solutions was appreciably higher, thus indicating the positive impact of low salinity water on foam stability. Additionally, anionic LSS solutions displayed reduced surfactant adsorption behavior onto sandstone cores, whereas for cationic LSS solutions the adsorption values were comparatively higher and exhibited a reverse adsorption trend with decreasing salinity. Finally, core flooding experiments illustrated that significantly higher residual oil could be mobilized and recovered through the tertiary immiscible low salinity surfactant alternating gas/CO2 (LSSAG) flooding. Nearly 23% original oil in place (OOIP) was produced by employing anionic LSS solution as the chemical slug during the LSSAG flooding. However, under similar experimental conditions, LSSAG flooding with cationic LSS solution recovered only about 16 %OOIP despite its comparatively better wettability alteration and IFT performance. In summary, using anionic LSS solutions constitute an effective means to suitably improve the performance of immiscible SAG flooding in sandstone reservoir cores.

Effect of Salinity on the Imbibition Recovery Process of Tight Sandstone Reservoirs

Fracture network fracturing combined with oil–water infiltration and replacement is an effective approach to develop tight sandstone reservoirs. How to further improve oil recovery based on imbibition is a problem encountered during production. In this study, the core of the CHANG-7 tight sandstone reservoir in the Changqing oilfield of the China National Petroleum Corporation (CNPC) is studied. Combined with the newly designed core self-imbibition experiment, the mechanisms of salinity action are studied, and the influence of salinity on the process of imbibition oil recovery is quantitatively characterized. Research results show that the influence of salinity on the imbibition process of tight sandstone reservoirs takes place mainly through two ways; one is to reduce the oil–water interfacial tension, and the other is to construct an osmotic pressure displacement model. The salinity has significant influences on interfacial tension. The interfacial tension of low-salinity brine is only 1/5 of that of distilled water, but in the presence of high-efficiency surfactants, the influence of the salinity on the interfacial tension can be ignored; the greater the difference in salt concentration, the higher the core permeability and the greater the influence of salinity on the process of imbibition and oil recovery in tight sandstone reservoirs. At the initial stage of imbibition, the effect of salinity is less important than that of capillary force. On the contrary, the effect of salinity is much more important than that of capillary force in the middle of imbibition, and the imbibition curve shows a downward trend. At the later stage of imbibition, the fluid tends toward imbibition equilibrium, and the effects of capillary force and salinity are not obvious.

Interfacial Tension Test Analysis as Injection Fluid on Reservoir Core

Interfacial Tension Test Analysis as Injection Fluid on Reservoir Core

Reproducing wettability in sandstone reservoir core material in laboratory core restorations

Replicating initial reservoir wettability conditions in core restoration by core cleaning and fluid restoration in the laboratory is of great importance. There are several core cleaning and restoration protocols used in the oil industry and academia that include the usage of different equipment, techniques, and materials. Strong solvents used in core cleaning can remove material that is part of the rock phase leading to more water–wet behavior. Large volumes of crude oil exposure in core restorations can result in high adsorption of polar organic components onto the mineral surfaces giving less water–wet behavior. Therefore, sufficient core cleaning should be targeted, involving no physical damage to the solid rock phase and effective crude oil exposure securing realistic water saturations, avoiding overexposure of crude oil. The objective of this study was to establish an optimum core restoration process in terms of cleaning solvents and the amount of crude oil exposure, to re-establish the same core wettability from one core restoration to the next. Seven sandstone cores from a reservoir on the Norwegian Continental Shelf underwent a series of core restorations. Two different core cleaning procedures were used, in which mild (kerosene/heptane) and strong (toluene/methanol) solvents were involved, and furthermore, the cores were exposed to various volumes of crude oil. Spontaneous imbibition experiments showed that mild core cleaning in combination with 5 pore volumes or more crude oil exposure rendered the cores less water-wet in successive core restorations. More rigorous cleaning with 5 pore volumes of crude oil exposure rendered the cores more water-wet in successive core restorations. From spontaneous imbibition results it was concluded that an optimum core restoration procedure involving mild cleaning and only 1 pore volume of crude oil exposure successfully reproduced core wettability in successive experiments.

A core-based XRF scanning workflow for continuous measurement of mineralogical variations in clastic reservoirs

Clastic reservoir core is routinely characterized using conventional, destructive spot sampling techniques. Whilst spot sampling provides useful textural and compositional information, the samples are typically widely spaced (∼ 25 cm), and hence continuous variation in rock composition/texture is not fully captured. It is therefore important to develop higher-resolution rock characterization techniques. In this paper, compositional data from a micro x-ray fluorescence (µXRF) scanner (hereafter Itrax) was used to demonstrate near-continuous (at 200 µm resolution) mineralogical variations in an ancient sandstone core. Traditionally, Itrax was used for compositional profiling of soft sediment cores, with limited use of this technology with rock cores. The acquired XRF data reveal subtle but systematic vertical compositional/textural trends, that may reflect distribution of major sandstone forming mineral grains, clay minerals, diagenetic carbonate cements and identification of new textural subdivisions in sandstones, which would not otherwise be seen with conventional plug analysis, implying the importance of high-resolution core scanning techniques for continuous measurement of mineralogy in clastic reservoirs.•Limited literature could be found whereby the capability of Itrax scanning has been extended to ancient, clastic cores.•Itrax is a non-destructive technique, where elemental composition is obtained directly at the surface of a split core at resolution significantly higher than conventional plug based techniques.•Itrax data acquisition is a quick process (few hours) and mineral distribution trends can be used as guide for further specialized sampling and detailed investigation of clastic reservoirs.